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A subsidiary of Pinnacle West Capital Corporation

Q085

System Impact Study

By

Arizona Public Service Company Transmission Planning

July 23, 2010

Version 1.0

Prepared by Jennifer Geer, P.E. (Utility System Efficiencies, Inc.)

Ryan Stewart (APS)

System Impact Study APS: Q085

of 58

Table of Contents

1. Executive Summary ................................................................................................................ 3 2. Study Assumptions ................................................................................................................. 6

2.1. Project Assumptions ......................................................................................................... 6 3. Power Flow Cases ................................................................................................................... 7

3.1. 2011 Cases........................................................................................................................ 7 3.2. 2013 Case ......................................................................................................................... 7 3.3. 2014 Case ......................................................................................................................... 7 3.4. Case Attributes ................................................................................................................. 8

4. Study Methodology ............................................................................................................... 10 4.1. Power Flow Analysis ..................................................................................................... 10 4.2. Voltage Flicker Analysis ................................................................................................ 11 4.3. Transient Stability Analysis ........................................................................................... 11 4.4. Post-transient Analysis ................................................................................................... 12 4.5. Short Circuit Analysis .................................................................................................... 13

5. Study Results ........................................................................................................................ 14 5.1. Power Flow .................................................................................................................... 14 5.2. Voltage Flicker ............................................................................................................... 15 5.3. Transient Stability .......................................................................................................... 16 5.4. Post-transient Governor Power Flow ............................................................................. 16 5.5. Short Circuit ................................................................................................................... 17 5.6. Mitigation ....................................................................................................................... 17

6. Cost and Construction Schedule Estimates........................................................................... 18 6.1. Interconnection Costs and Schedule Estimate ............................................................... 18 6.2. Network Upgrades Estimates ......................................................................................... 19

Appendix A – Power Flow Plots Appendix B – Transient Stability Modeling Appendix C – Transient Stability Plots Appendix D – Hyder 69 kV Ring Bus One-Line Diagram Appendix E – Overhead 69 kV Line Work Diagram


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1. Executive Summary Solar Reserve, the Interconnection Customer (IC), submitted a Small Generator Interconnection Request (IR) to Arizona Public Service Company (APS) for their proposed Hyder 1 (Project), located approximately four miles north of Hyder Substation, near Hyder, Arizona. The Interconnection Customer (IC) has requested Energy Resource Interconnection Service and plans to install 20 MW of photovoltaic solar generation with an In-Service Date of March 31, 2011. The Project’s requested Point of Interconnection (POI) is the Hyder Substation’s 69 kV bus. The Project is Queue Position 85 (Q085) in the APS generation interconnection queue. The IC elected to bypass the Interconnection Feasibility Study and proceed directly to a System Impact Study (SIS). The SIS determined the following:

1. Preliminary identification of any thermal overload or voltage limits violations resulting from the interconnection.

2. Preliminary identification of any transient stability violations resulting from the interconnection.

3. Preliminary identification of any post-transient governor power flow violations resulting from the interconnection.

4. Preliminary identification of any circuit breaker short circuit capability limits exceeded as a result of the interconnection.

5. Preliminary list of facilities, a non-binding good faith estimate of cost responsibility and a non-binding good faith estimated time to construct facilities necessary to interconnect the Project.

DISCLAIMER

Nothing in this report constitutes an offer of transmission service or confers upon the Interconnection Customer, any right to receive transmission service. APS and other interconnected utilities may not have the Available Transmission Capacity (ATC) to support the interconnection described in this report. It should also be noted that the results in this SIS are dependent upon the assumed topology and timing of new projects in the Gila Bend area, which are subject to change. The APS transmission and sub-transmission systems are continuously being evaluated. The planned reinforcements and their in-service dates are often revised depending upon local area load forecasts.


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Figure 1.1 below shows a single line diagram of the APS 69 kV system in the Project vicinity.

Figure 1.1: Single Line Diagram of 69 kV in the Project Vicinity

The Project was studied under 2011 heavy summer conditions. The 2011 heavy summer scenario represents the time of interconnection of the Project. In addition, thermal sensitivity studies were conducted under 2013 and 2014 heavy summer conditions. The 2013 and 2014 sensitivities include planned system topology changes as well as the higher queued generation projects in the area and their associated system upgrades.

RESULTS:

The results of the power flow analyses indicate the Project triggered an overload on the Gila Bend-Paloma 69 kV line at full dispatch for the outages of Saddle Mtn-Buckeye 69 kV and Hyder- Saddle Mtn 69 kV. Reducing the Project output to 10 MW would eliminate the overload. The 2011 power flow results showed no voltage violations caused by the Project. However, in 2013 and 2014 the addition of the Project caused a voltage deviation of 5.1% at Saddle Mtn 69 kV for the N-1 loss of Saddle Mtn-Buckeye 69 kV. This contingency was checked with a 2014 post transient governor power flow solution which validated the 5.1% voltage deviation at Saddle Mtn 69 kV. If the Project capacitor is split into a minimum of two equal steps and operated post-contingency to have a lagging pf, such as 0.98 lagging, the voltage deviation violation is eliminated.

BunyanSubstation

HyderSubstation

AztecSubstation

HornSubstation

Saddle MountainSubstation

36 MVA 36 MVA

64 M

VA

POI

69/12kV9.4 MVA

39

MVA

Q85 (20 MW)

~

13.8 kV 69kV


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The 2011 transient stability analysis concluded that the Project did not cause any transient stability violations for the studied contingency simulations. The 2011 post-transient governor power flow analysis determined that the Project caused voltage deviation violations by increasing the voltage over 5% at 8 buses for the Hyder-Saddle Mtn 69 kV outage (including 2 Project buses). This can be addressed by tripping the Project or having the Project install fast, segmented, reactive compensation to control pf and voltage at the POI.

The 2011 short circuit analysis indicates no equipment short circuit ratings in the vicinity of the Q085 generation were exceeded as a result of the Project. POI Requirements The APS OATT (Open Access Transmission Tariff) policy regarding power factor requires any

Interconnection Customer to maintain an acceptable power factor (typically near unity) at the POI, subject to system conditions. APS also requires the Interconnection Customer to be able to adjust the power factor within the range of +/- 0.95, as long as the Project is connected to the grid, whether generating or not. The Project may disconnect itself temporarily, such as at night when the Project is not generating, to avoid these requirements. APS has the right to disconnect the Project if system conditions dictate the need.

Project Costs Table 1.1 below provides a summary of the total project costs and timelines for interconnecting Q085 to the Hyder Substation. A more detailed breakdown can be found in Section 6. Table 1.1: Q085 Cost Summary Facility Costs Timeline Network Upgrades $5,715,000 22 Months Q085 Trans. Provider's Interconnection Facilities $143,000 12 Months

Total $5,858,000 22 Months As can be seen in Table 1.1 above, the total estimated completion time for interconnecting the Q085 project is 22 months. Therefore, the desired In-Service Date of March 31, 2011 cannot be met. APS and the Interconnection Customer must therefore discuss and mutually agree to a new and acceptable projected In-Service Date.


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2. Study Assumptions

2.1. Project Assumptions The following Project assumptions were used for this study: 1. The Project is a 20 MW photovoltaic solar generation project. Major components of the

Project include a four (4) mile 69 kV gen-tie, a single 69/13.8 kV station transformer, a 13.8 kV collector system, ten (10) 13.8/0.48 kV padmount transformers and forty (40) Satcon 500 kW inverters.

2. The Project is located approximately four (4) miles from the Hyder Substation 3. The IC requested Energy Resource (ER) interconnection service to the Hyder Substation 69

kV bus. 4. The planned In-Service Date is March 31, 2011. 5. The gen-tie was modeled as four miles of 3/0 ACSR with a continuous rating of 39/39 MVA.

The positive sequence impedance of the line was modeled as R1pu=0.0520, X1pu=0.0634 and B1pu=0.0006 on a 100 MVA and 69 kV base.

6. The main Project transformer was modeled as a 25 MVA 69 kV/13.8 kV transformer. Z = 7 % on 25 MVA base with X/R = 10.

7. The generation was modeled as a single 20 MW generator with unity pf at the 13.8 kV bus. To simulate the losses downstream of the 69/13.8 kV transformer, a load of 0 MW and 4.06 MVAr was added at the Project’s 13.8 kV bus, to model an assumed pf of 0.98 lagging.

8. The VAr capability for the Project was assumed to be zero. To generate a net zero VAr flow from the Project at the POI for the N-0 (all lines in service) scenario, capacitance was added to the Project’s 13.8 kV bus (approximately 4.9 MVAr at 1.04 per unit voltage at the 13.8 kV bus).

Figure 2.1: Q085 Interconnection

69 kV

25 MVA69/13.8 kVZ = 7%

P = 0 MWQ = 4.06 MVArAssumed losses (0.98 pf)

20 MW

Hyder 69 kV

POI Gen-tie

13.8 kV

Cap to produce ~ 0 VAr flow at POI


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3. Power Flow Cases Cases were created for 2011, 2013 and 2014. The 2011 cases represent the year of interconnection. The 2013 and 2014 cases were used to check the sensitivity of the thermal analysis results.

3.1. 2011 Cases Two 2011 cases were developed: one for the power flow analysis and one for the transient stability analysis. Both of the 2011 cases were developed from APS detailed planning base cases, which were jointly built by the Arizona utilities. They include the latest load forecast for 2011. The thermal case includes the entire APS 69 kV system, and was developed from APS Detailed Planning Study case “sm11#13.sav”. The transient case was developed from APS Detailed Planning Study case “sm10#15.sav” and includes the Buckeye/Gila Bend 69 kV system, but not all of the neighboring APS 69 kV sub-transmission system. The following nearby generation interconnection projects and their recommended plans of service were included: Energy Resource (ER): Q031, Q077, Q084

3.2. 2013 Case The 2013 case was used to check the sensitivity of the thermal analysis results. The 2013 Heavy Summer power flow case originated from the West Connect 2013 Heavy Summer Bulk System, WECC 12hs2s case, dated November 9, 2007. Detailed APS, Salt River Project (SRP), and Imperial Irrigation District (IID) models were added to the case. The 2013 pre-project case was finalized by adding all the Network Resource (NR) generation with higher queue positions. These higher queue position NR generators represent approximately 3000 MW and were dispatched by offsetting (turning off) select APS combustion turbines (CTs) and gas turbines (GTs) as well as PV Hub combined cycle units including the Redhawk and Arlington plants and parts of Mesquite plant. The following nearby Network Resource (NR) generation interconnection projects and their recommended plans of service were included: Q043, Q044, Q044b, Q045, Q051, Q056, Q058, Q059, Q060, Q063, and Q067. Nearby 12 kV and 69 kV Energy Resource (ER) projects were also included: Q031, Q077, Q084

3.3. 2014 Case The 2014 case was built from the above 2013 case, but was updated to include the Delany-Sun Valley 500 kV line, Sun Valley 500/230 kV transformer, the Sun Valley-Trilby Wash 230 kV line and the Sun Valley-Hassayampa Pump 230 kV line. Two higher queued NR projects were also added: Q038 and Q039.


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3.4. Case Attributes A summary of the case attributes is shown below. Table 3.1: Project Power Flow Case Attributes (MW)

Year/Season 2011

Heavy Summer “Thermal”

2011 Heavy Summer

“Trans”

2013 Heavy Summer

“Thermal”

2014 Heavy Summer

“Thermal”

Base Case Pre Case

Post Case

Pre Case

Post Case

Pre Case

Post Case

Pre Case

Post Case

Path 50 Cholla-Pinnacle Peak 781 781 690 645 794 794 791 791

Path 54 Coronado West 1,008 1,008 755 751 1,068 1,068 1,070 1,071

Gila Bend 230/69 kV 12 18 16 20 49 61 47 59

Buckeye 230/69 kV 148 127 114 90 141 119 147 124.2

Area 14 – Arizona

Load 19,607 19,607 19,478 19,478 22,527 22,527 22,504 22,504 Losses 700 700 507 499 959 962 966 968 Gen 27,817 27,817 26,996 26,987 31,523 31,525 31,507 31,509 Interchange 7,510 7,510 7,010 7,010 8,037 8,037 8,037 8,037 Area 73 – WAPA R.M.

Load 5,092 5,092 5,092 5,092 5,697 5,697 5,697 5,697 Losses 175 175 181 181 187 187 187 187 Gen 6,256 6,256 6,263 6,262 6,584 6,584 6,584 6,584 Interchange 990 990 990 990 704 704 704 704


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Figure 3.1: System Topology near Q0851

1 The above map shows approximate locations for planned generation. It is shown for information only, to provide an indication of the quantity of planned generation in the area. The generation projects shown are not necessarily modeled in the cases.


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4. Study Methodology This System Impact Study consists of power flow, voltage flicker, transient, post-transient governor power flow, and short circuit analysis in order to identify a preliminary list of facilities, a non-binding good faith estimate of cost responsibility and a non-binding good faith estimated time to construct facilities necessary to interconnect the projects in the group. Table 4.1: Study Summary # Description 2011 2013 2014 1. Power flow √ √ √ 2. Flicker √ 3. Transient Stability √ 4. Post-Transient Stability √ 5. Short Circuit Analysis √

4.1. Power Flow Analysis For normal conditions, automatic transformer taps, static VAr devices (SVD) and phase-shifting transformers (PST) were allowed to adjust in solving the power flow cases. For contingency simulations, the power flow analysis considers a snapshot in time where automatic transformer taps and SVDs are allowed to adjust, while PSTs remain fixed; in addition, a system swing bus balances the system during each contingency scenario. Areas 14 (Arizona) and 73 (WAPA R.M.) were monitored. Power flow analysis was performed using the NERC/WECC planning standards. Power flow analysis was used to evaluate thermal and voltage performance of the transmission system for NERC/WECC Category A normal (all elements in-service) conditions, selected NERC/WECC Category B emergency (one element out of service) conditions and selected NERC/WECC Category C emergency (multiple elements out of service) conditions. Category A (N-0) normal overloads are those that exceed 100% of normal ratings that occur with all facilities in service. Category B and C emergency overloads are those that exceed 100% of emergency ratings that occur due to a Category B or C contingency. All power flow analysis was conducted with version 17.0_06 of General Electric’s PSLF/PSDS/SCSC software. Reported normal thermal loading was limited to the condition where a modeled transmission component was loaded above 80% of the normal MVA rating (Rating 1 as entered in the power flow case), as well as the condition in which the incremental increase in component loading, between pre-project and post-project, exceeded 1%. Reported emergency thermal loading was limited to the condition where a modeled transmission component was loaded over 80% of its appropriate emergency MVA rating (Rating 2 as entered in the power flow case), as well as the condition in which the incremental increase in component loading, between pre-project and post-project, exceeded 1%.


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Reported normal voltage violations were limited to the conditions where per unit (pu) voltages were less than 0.95 or greater than 1.05 (less than 1.00 and greater than 1.10 for 500 kV buses). Reported Category B and C emergency voltage violations were limited to the conditions where per unit voltages were less than 0.90 or greater than 1.10. In addition, only Category B voltage deviations greater than 5% between the pre and post-contingency and a 1% increase in voltage deviation between the pre and post-project power flow cases were recorded and only Category C voltage deviations greater than 10% between the pre and post-contingency and a 1% increase in voltage deviation between the pre and post-project power flow cases were recorded.

4.2. Voltage Flicker Analysis Voltage flicker analysis was performed to determine if there were impacts from generation output variation on local area bus voltages.

4.3. Transient Stability Analysis Performance of the transmission system will be measured against the following planning criteria: the Western Electricity Coordinating Council (“WECC”) Reliability Criteria, and the North American Electric Reliability Council (“NERC”) Planning Standards. The reliability and performance criteria will be applied to the entire WECC transmission system.

a) Transient voltage dips and frequencies must meet the following WECC Reliability Criteria (WECC Table W-1 and NERC Table I). See Table 4.2 and Figure 4.1 below.

b) All machines in the system shall remain in synchronism as demonstrated by their relative rotor angles.

c) System stability is evaluated based on the damping of the relative rotor angles and the damping of the voltage magnitude swings.

Table 4.2 and Figure 4.1 are excerpts from the WECC Reliability Criteria.

Table 4.2: WECC Disturbance-Performance Table Of Allowable Effects On Other Systems NERC and

WECC Categories

Outage Frequency Associated with the

Performance Category

(outage/year)

Transient Voltage Dip Standard

Minimum Transient Frequency Standard

Post Transient Voltage Deviation Standard

(See Note 2)

A Not Applicable Nothing in addition to NERC

B ≥ 0.33

Not to exceed 25% at load buses or 30% at non-load buses. Not to exceed 20% for more than 20 cycles at load buses.

Not below 59.6Hz for 6 cycles or more at a load bus.

Not to exceed 5% at any bus.

C 0.033 – 0.33

Not to exceed 30% at any bus. Not to exceed 20% for more than 40 cycles at load buses.

Not below 59.0Hz for 6 cycles or more at a load bus.

Not to exceed 10% at any bus.

D < 0.033 Nothing in addition to NERC


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Figure 4.1: NERC/WECC Voltage Performance Parameters

Study Disturbances: The following fault clearing times were used: 4 cycles: 345 kV outages and above 5 cycles: 230 kV outages 6 cycles: 115 kV outages 7 cycles: 69 kV outages.

4.4. Post-transient Analysis A post-transient power flow analysis will be performed to determine if the voltage deviations at critical buses meet the maximum allowable voltage dip criteria for selected N-1 and N-2 disturbances.

• Loads will be modeled as constant power during the first few minutes following an outage or disturbance.

• All voltages at distribution substations will be restored to their normal values by the transformer tap changers and other voltage control devices.


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• Generator VAR limits will be modeled as a constant single value for each generator since the reactive power capability curve will not be modeled in the power flow program.

• Alpha min and Gamma min of the PDCI and IPPDC will be adjusted to 5 degrees and 13 degrees, respectively.

• Area Interchange Control is Disabled • Phase Shifter Control is Disabled • Governor Blocking per WECC Modeling & Validation Work Group

recommendations - Diablo, Palo Verde, and San Onofre • DC Line Transformer Tap Automatic Adjustment is Enabled • Generator Voltage Control set to local except for San Onofre, Palo Verde, and

selected Northwest generation • Automatic Control of Switched Shunt Devices is Disabled - except in Sierra Pacific

Power's system (Area 64) Study Criteria: The following criteria will be used to evaluate the post-transient voltage stability performance: a) Transient voltage dips should meet the following WECC Reliability Criteria (WECC

Table W-1 and NERC Table I):

Performance Level Disturbance Post Transient Voltage Deviations

B N-1 > 5% C N-2 > 10% D N-3 Cascading Not Permitted

4.5. Short Circuit Analysis Short circuit analysis was performed to determine the maximum fault currents on buses in the vicinity of the group. This study assessed the impact of increased fault duty resulting from the projects in the group for single line-to-ground and three-phase faults. Equipment that may become over-stressed as a result of the added generation was identified if the fault duty exceeds 100% of its applicable interrupting capability.


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5. Study Results

5.1. Power Flow Power flow analysis was performed on all pre and post-Project power flow cases. The results were compared to determine the impacts caused solely by the addition of the Project and to identify the system reinforcements necessary to mitigate the adverse impacts. These Pre-Project and Post-Project cases were evaluated for Category A (N-0 or all lines in service) conditions. Then approximately 60 Category B and 2 Category C contingencies were applied to the cases. Areas 14 (Arizona) and 73 (WAPA R.M.) were monitored. Voltage results focused on buses at 69 kV and above, as well as all Project buses. Select power flow plots are included in Appendix A. Overloads The results of the 2011, 2013 and 2014 power flow analyses indicate the Project triggered one new overload in the monitored systems of Arizona and WAPA R.M. The results are shown below.2

Table 5.1: 2011 N-1 Overloads

Emergency % Emergency Rating

Monitored Branch Contingency Description Rating (Amps) Pre

2011 Post 2011

GILABEND -PALOMA 69 kV N-1 SADDLEMT-BUCKEYE 69 kV 728 85 100.5 N-1 HYDER- SADDLEMT 69 KV 728 n/a 106.4

Table 5.2: 2013 and 2014 N-1 Overloads

Emergency % Emergency Rating

Monitored Branch Contingency Description Rating (Amps)

Pre 2013

Post 2013

Post 2014

GILABEND -PALOMA 69 kV N-1 SADDLEMT-BUCKEYE 69 kV 728 88 103.8 103.8 N-1 HYDER- SADDLEMT 69 KV 728 n/a 108.7 108.6

Reducing the Project output to 10 MW reduces the loading on Gila Bend-Paloma to 96% in 2011 and 98% in 2013 for the Hyder-Saddle Mtn outage, and eliminates the overload. Voltage N-0 The results showed no Project caused N-0 voltage violations. Voltage N-1 The 2011 power flow results indicated no voltage violations caused by the Project. In 2013 and 2014 the addition of the Project caused a voltage deviation of 5.1% at Saddle Mtn 69 kV for the N-1 loss of Saddle Mtn-Buckeye 69 kV. This contingency was checked with a 2014 post transient governor power flow solution which validated the 5.1 % voltage deviation at 2Though not Project-related, in 2014 the Palo Verde-Delany 500 kV outage causes the case solution to diverge without the applicable SPS, opening the Hassayampa Tap-Hassayampa Pump 230 kV line and/or tripping nearby generation. Detailed discussion is not part of this report.


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Saddle Mtn 69 kV. If the Project capacitor is split into a minimum of two equal steps and operated post-contingency to have a lagging pf, such as 0.98 lagging, the voltage deviation violation is eliminated.

POI Requirements The APS OATT (Open Access Transmission Tariff) policy regarding power factor requires any

Interconnection Customer to maintain an acceptable power factor (typically near unity) at the POI, subject to system conditions. APS also requires the Interconnection Customer to be able to adjust the power factor within the range of +/- 0.95, as long as the Project is connected to the grid, whether generating or not. The Project may disconnect itself temporarily, such as at night when the Project is not generating, to avoid these requirements. APS has the right to disconnect the Project if system conditions dictate the need.

5.2. Voltage Flicker Without detailed information on the collector system, two Project loss scenarios were reviewed. The first assumes worst case, or constant Project losses. The second table assumes the Project losses decrease proportionally to the generation and that the Project capacitor is kept fully on to support the voltage. Tables 5.4 and 5.5 show the results from the flicker study. Although voltage deviations greater than 1% are highlighted, it was determined that flicker was not a concern due to the slower speed at which the photovoltaic generation will adjust. Table 5.4: 2011 Voltage Flicker - Assuming losses stay constant as the generation drops

Table 5.3: 2014 N-1 Voltage BUS NAME CONTINGENCY DESCRIPTION Base PU Cont PU Deviation Base PU Cont PU Deviation SADDLEMT 69.00 N-1 SADDLEMT-BUCKEYE 69kV 0.9924 1.0433 5.1300 0.9849 1.0220 3.7000

Post Q85 1step capacitor Post-Q85 2 step capacitor

Bus Volt (pu) Volt (pu) Deviation Volt (pu) Deviation Volt (pu) Deviation Volt (pu) DeviationQ085 69.00kV 1.0325 1.0005 -0.0319 1.0091 -0.0233 1.0203 -0.0121 1.0297 -0.0027HYDER 69.00kV 1.0224 0.9989 -0.0234 1.0055 -0.0169 1.0138 -0.0086 1.0205 -0.0019AZTEC 69.00kV 1.0314 1.008 -0.0234 1.0145 -0.0169 1.0229 -0.0086 1.0295 -0.0019HORN 69.00kV 1.0213 0.9977 -0.0236 1.0043 -0.017 1.0127 -0.0086 1.0194 -0.0019SADDLEMT 69.00kV 0.9968 0.9871 -0.0098 0.9902 -0.0066 0.9938 -0.003 0.9963 -0.0006BUNYAN 69.00kV 1.0389 1.0334 -0.0055 1.0354 -0.0035 1.0375 -0.0014 1.0387 -0.0002PALOMA 69.00kV 1.0443 1.0436 -0.0007 1.0441 -0.0002 1.0445 0.0001 1.0444 0.0001GILABEND 69.00kV 1.0317 1.0328 0.0011 1.0327 0.001 1.0325 0.0007 1.0319 0.0002BUCKEYE 69.00kV 1.0304 1.0308 0.0003 1.0308 0.0004 1.0307 0.0003 1.0305 0.0001

100% Generation (base) 10% Generation 30% Generation 60% Generation 90% Generation


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Table 5.5: 2011 Voltage Flicker - Proportional Project losses, Project capacitor on full

5.3. Transient Stability The results of the 2011 transient stability analysis indicate that the Project did not trigger any transient stability violations. See Appendix B for the Transient Stability Modeling and Appendix C for select Transient Stability Plots.

5.4. Post-transient Governor Power Flow The results of the post-transient governor power flow analysis indicate that the Project caused voltage deviation violations by increasing the voltage over 5% at 8 buses for the Hyder-Saddle Mtn 69 kV outage. Table 5.6: Hyder-Saddle Mtn 69 kV Outage

This can be addressed by tripping the Project or, if the Project can respond quickly enough, changing the Project reactive compensation from a 1.0 pf to a 0.98 lagging pf at the POI.

Bus Volt (pu) Volt (pu) Deviation Volt (pu) Deviation Volt (pu) Deviation Volt (pu) DeviationQ085 69.00kV 1.0325 1.0182 -0.0143 1.0228 -0.0096 1.0282 -0.0042 1.0317 -0.0007HYDER 69.00kV 1.0224 1.0142 -0.0082 1.0174 -0.005 1.0207 -0.0017 1.0222 -0.0001AZTEC 69.00kV 1.0314 1.0232 -0.0082 1.0264 -0.005 1.0297 -0.0017 1.0313 -0.0001HORN 69.00kV 1.0213 1.0131 -0.0082 1.0163 -0.005 1.0196 -0.0017 1.0212 -0.0001SADDLEMT 69.00kV 0.9968 0.9972 0.0004 0.9982 0.0013 0.9985 0.0016 0.9975 0.0006BUNYAN 69.00kV 1.0389 1.0416 0.0028 1.0418 0.0029 1.0412 0.0024 1.0396 0.0008PALOMA 69.00kV 1.0443 1.0467 0.0024 1.0465 0.0022 1.0459 0.0015 1.0448 0.0005GILABEND 69.00kV 1.0317 1.0346 0.0029 1.0342 0.0024 1.0333 0.0015 1.0322 0.0004BUCKEYE 69.00kV 1.0304 1.0317 0.0013 1.0315 0.0011 1.0311 0.0007 1.0306 0.0002

100% Generation (base) 10% Generation 30% Generation 60% Generation 90% Generation

Bus Name kVVolt

DeviationAZTEC 69 5.6AZTEC 12 5.8HORN 69 5.7HORN 12 5.8HYDER 69 5.7HYDER 12 5.7Q085 69 5.6Q085_GEN 12 5.7


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5.5. Short Circuit Short circuit analysis of the proposed generator interconnection was performed by the APS Protection Department, using the CAPE program and parameters supplied by the IC. Single line-to-ground (SLG) and three-phase faults were simulated with and without the Project to determine if there are any overstressed circuit breakers caused by the addition of the Project. Study results indicate there are no circuit breaker fault duty limit violations attributable to the Q085 Project. The short circuit results can be seen in Table 5.7 below. Table 5.7: Q085 Short Circuit Results

Fault Study

Base Case With Q085 Min. Breaker Substation 3 Ph. (kA) Ph-G (kA) 3 Ph. (kA) Ph-G (kA) Rating (kA) Bunyan 69 kV 2.9 3.5 3.3 2.3 40 Hyder 69 kV N/A N/A 2.9 2.7 As required Saddle Mountain 69 kV 2.0 1.1 2.2 1.4 40

5.6. Mitigation Unless the Project reduces its dispatch level to 10 MW, mitigation is required to address the overload on the Gila Bend-Paloma 69 kV line as described in section 5.1.

• Upgrade the Gila Bend-Paloma line to 795 ACSS conductor (7 miles).

In addition, the post-transient violations in 2014 resulting from the Hyder-Saddle Mtn 69 kV outage should be addressed. (See section 5.4)

• A future Special Protection Scheme (SPS) to trip Q085 for the Hyder-Saddle Mtn 69 kV outage or installation of fast, segmented, reactive compensation within the Project to control pf and voltage at the POI (i.e. – inverter reactive capabilities, capacitor banks, etc).


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6. Cost and Construction Schedule Estimates The cost and time estimates represent good faith estimates necessary to interconnect to the system. The costs do not include any costs for new rights-of-way that may potentially be needed for some upgrades or for Transmission Line Siting activities that would need to be performed. The non-binding, good faith cost and time estimates are tabulated below.

6.1. Interconnection Costs and Schedule Estimate

The cost estimates for the various parts of the Q085 Interconnection Project are listed in more detail in Sections 6.2 and 6.3 below. Table 6.1 below provides a summary of which costs are considered Network Upgrades and which are Transmission Provider’s Interconnection Facilities. Table 6.1: Q085 Project Cost Summary Equipment Description Network Upgrades Transmission Provider's

Interconnection Facilities Hyder Ring Bus $1,997,000 $143,000 Hyder 69 kV Line Work $800,000 $0 Communications (Microwave) $218,000 $0 Gila Bend-Paloma 69 kV Rebuild $2,700,000 $0 Land Services/Siting/Permit/Etc $0 $0 Subtotal $5,715,000 $143,000 Grand Total $5,858,000

The facilities identified in Table 6.1 above as Transmission Provider’s Interconnection Facilities (also shown in blue in Appendix D) would be the sole cost of the Interconnection Customer. Unlike Network Upgrades, these costs are not reimbursable. The Interconnection Customer’s desired In-Service Date for the Interconnection Facilities is March 31, 2011. Table 6.2 below provides a summary of the estimated construction schedules. Table 6.2: Construction Time Estimates

Facility Schedule

Design Construction

Hyder 69 kV Ring Bus 6 Months 6 Months Hyder 69 kV Line Work 9 Months 3 Months Communications 6 Months 6 Months Gila Bend-Paloma 69 kV Rebuild 10 Months 12 Months

Total 22 Months * All the above work can be completed in parallel with each other


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The summary provided in Table 6.2 above shows a total estimated completion time of 22 months, which is due to the Gila Bend-Paloma 69 kV rebuild. The two main reasons for the long completion time is 1) the long lead time for materials, and 2) this section of 69 kV line only has a 5-6 month window in which it can be taken out of service. Since this rebuild would need to be in-service at the same time as the Q085 project, the total completion time to interconnect Q085 to the APS 69 kV transmission system would be 22 months. Therefore, the desired In-Service Date of March 31, 2011 cannot be met. APS and the Interconnection Customer must therefore discuss and mutually agree to a new and acceptable projected In-Service Date.

6.2. Network Upgrades Listed in Table 6.3 below are the cost estimates associated with the Network Upgrades required for the Q085 project. These upgrades consist of expanding APS’s Hyder 69 kV substation into a 5-element ring bus. A one-line of the new Hyder ring bus can be seen in Appendix D (Network Upgrades shown in green). The addition of breakers at Hyder substation will cause the normally open Hyder – Saddle Mtn 69 kV line to become normally closed

. The new ring bus will also require rebuilding the Saddle Mtn 69 kV tap to double-circuit for approximately ¾ mile (see Appendix E). This rebuild will bring both the Bunyan and Saddle Mtn 69 kV lines into the new Hyder ring bus. The rebuild of the Gila Bend-Paloma 69 kV line (identified as an overload in Section 5.1 above) would also be considered Network Upgrades.

The assumptions used for the 69 kV line & substation estimates are as follows: Line construction estimate based on one 5-person crew Rebuilds are assumed that lines will be rebuilt in existing location Terrain was not considered when estimating line route Environmental studies will be required on new and existing lines crossing federal lands Access and lay down yards are not included in the estimate Land costs for expansion of the Hyder 69 kV substation are not included in the estimate Rough grading costs are not included in the estimate 120’ x 120’ minimum space required for control house (drainage may require additional

land) APS will construct, own and operate the facilities in the Hyder substation and the portion

of 69 kV line from the Hyder 69 kV bus up to the first structure outside the sub fence The IC will construct, own and maintain the 69 kV gen-tie from the APS Hyder

substation to the Q085 site The IC will be responsible for providing a fiber optic communications path from the

Q085 facility to the Hyder substation All estimates are in 2010 dollars


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Table 6.3: Network Upgrade Cost Estimates Equipment Description Hyder 5-Element

Ring Bus Hyder 69 kV Line Work

Gila Bend-Paloma 69 kV Rebuild

Engineering and Design $320,000 $23,000 $103,000 Below Grade Construction $327,000 $0 $0 Above Grade Construction Labor (Steel, Bus, & Equipment) $205,000 $336,000 $1,674,000

Control/Relay Labor $220,000 $0 $0 Steel Structures $84,000 $341,000 $439,000 Equipment/Relay/RTU/Security $841,000 $100,000 $484,000 Communications (Microwave) $218,000 $0 $0 Land Services/Siting/Permit/Etc $0 $0 $0 Subtotal $2,215,000 $800,000 $2,700,000 Grand Total $5,715,000

The costs of all Network Upgrades identified above in Table 6.3 would typically be repaid to the Interconnection Customer, per FERC rules, as transmission credits over a maximum of twenty (20) years.

6.3. Transmission Provider’s Interconnection Facilities Listed in Table 6.4 below are the cost estimates associated with the Transmission Provider’s Interconnection Facilities required for the Q085 project. These facilities include the necessary switches, bus work, etc. needed to bring the Q085 69 kV generation tie-line into the Hyder ring bus. The facilities are shown in blue in Appendix D. These costs are the sole responsibility of the Interconnection Customer, and will not be reimbursed. Table 6.4: Transmission Provider’s Interconnection Facilities Cost Estimate Equipment Description Hyder 5-Element

Ring Bus Engineering and Design $19,000 Below Grade Construction $10,000 Above Grade Construction Labor (Steel, Bus, & Equipment) $12,000

Control/Relay Labor $18,000 Steel Structures $8,000 Equipment/Relay/RTU/Security $76,000 Communications (Microwave) $0 Land Services/Siting/Permit/Etc $0 Subtotal $143,000 Grand Total $143,000


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APPENDIX A

Power Flow Plots

Plot Listing:

Figure # Base Case Case Figure 1: N-0 2011 Pre Case Figure 2: N-0 2011 Post Case Figure 3: N-1 2011 Post Case Figure 2a: N-0

N-0 2013 Pre Case

Figure 2b: 2013 Post Case


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Figure 1: 2011 Q085 Pre Case N-0


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Figure 2: 2011 Q085 Post Case N-0


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Figure 3: 2011 Q085 Post Case N-1 Hyder-Saddle Mtn 69kV


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Figure 4: 2013 Q085 Pre Case N-0


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Figure 5: 2013 Post Case N-0


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APPENDIX B

Transient Stability Modeling


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Plant Dynamic Model Data utilizing Satcon PV Inverters

Q085Constant Description From ICrsrc Source resistance, pu on plant base 0.000xsrc Source reactance, pu on plant base 0.000Vratio Ratio of PV array open circuit to peak power voltage 1.4Iratio Ratio of PV array short circuit to peak power current 1.2Tdc Inverter DC capacitor bank time constant, sec 0.0014Kpdc DC voltage regulator proportional gain 3.0Kidc DC voltage regulator integral gain 10Ilim Inverter AC current limit, thermal limit, pu/sec 1.1OV1L Overvoltage trip point #1, pu 1.3OV1T Overvoltage delay #1, sec 0.16OV2L Overvoltage trip point #2, pu 1.1OV2T Overvoltage delay #2, sec 1.0UV1L Undervoltage trip point #1, pu 0.5UVIT Undervoltage delay #l, sec 0.16UV2L Undervoltage trip point #2, pu 0.88UV2T Undervoltage delay #2, sec 1.0OFL Overfrequency trip point, pu 60.5OFT Overfrequencv delay, sec 0.16UFL Underfrequency trip point, pu 59.5UFT Underfrequency delay, sec 0.16QREG Reactive power mode flag 1.0RRMAX Maximum real current rate limit 1.0RRMIN Minimum real current rate Limit -999.0IRMAX Maximum imaginary current rate limit 1.0IRMIN Minimum imaginary current rate Limit -1.0LRMAX Maximum limiting current rate limit 1.0LRMIN Minimum limiting current rate limit -1.0

Input Parameters


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APPENDIX C

Transient Stability Plots


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Transient Stability Analysis was run on each of the contingencies listed in the table below. This appendix includes a sampling of the plots that were created, which are highlighted in grey. Plots for the remaining contingencies may be obtained on request.

Contingency #51 intentionally trips the Project generation.

Contingency # Pre Post!N-0_FLAT_RUN Flat √ √sw03-500-HAS-JJB-slo 3 √ √sw04-500-HAS-NGI-slo 4 √ √sw05-500-HAS-PNW-slo 5 √ √sw06-500-JJB-KYR-slo 6 √ √sw07-500-KYR-BRN-slo 7 √ √sw08-500-PVD-RUD-slo-TS 8 √ √sw09-500-PVD-WWG-1-slo-TS 9 √ √sw10-500-PVD-WWG-2-slo-TS 10 √ √sw12-500-JJB-GIL_1 12 √ √sw13-500-JJB-GIL-2 13 √ √sw14-230-GBD-PAN-5c-slo 14 √ √sw16-230-RUD-PVL_5c_slo 16 √ √sw17-230-BUK-LIB-wSPS-5c-slo 17 √ √sw19-RUD_500_230_1 19 √ √sw20-RUD_500_230_2 20 √ √sw21-RUD_500_230_3 21 √ √sw22-RUD_500_230_4 22 √ √sw23-GIL_500_230_1 23 √ √sw24-KYR_500_230_6 24 √ √sw25-KYR_500_230_7 25 √ √sw27-GLB_230_069_1 27 √ √sw28-GLB_230_069_2 28 √ √sw30-BUK_230_069_1 30 √ √sw31-BUK_230_069_2 31 √ √sw32-69-gil-thay-slo 32 √ √sw33-69-thay-why-slo 33 √ √sw34-69-gil-gillespi-slo 34 √ √sw35-69-gillespi-buck-slo 35 √ √sw36-69-pvngpump-baseline-slo 36 √ √sw37-69-buckeye-watsonw-slo 37 √ √sw39-69-gillwest-pvngpump-slo 39 √ √sw40-69-pvngpump-winter-slo 40 √ √sw41-PRE/PST 69-saddlemt-buckeye 41 √ √sw42-69-gil-bun-slo_PRE-r1 42 PRE √sw42-69-gil-bun-slo_PRE_xfr-r1 42 PRE √sw42-69-gil-bun-slo_PST-r1 42 PST √sw43-69-bun-horn-slo_PRE-r1 43 PRE √sw44-69-bun-hyder-slo_PST 44 PST √sw45-69-hyder-horn-slo_PST-r1 45 PST √sw46-69-hyder-saddlemt-slo_PST 46 PST √sw50-69-paloma-q031-slo 50 √ √sw51-69-hyder-q085-slo_PST 51 PST √sw63-500-HAS-JJB-PNW-dlo 43 √ √sw64-GIL-JJB_500_1-2_wSPS 44 Gen trip at Detroit-stable


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APPENDIX D

Hyder 69 kV Ring Bus One-Line Diagram


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APPENDIX E

Overhead 69 kV Line Work Diagram


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